Annular fluids or packer fluids are liquids which are pumped into annular openings such as, for example, (1) between a wellbore wall and one or more casing strings of pipe extending into a wellbore, or (2) between adjacent, concentric strings of pipe extending into a wellbore, or (3) in one or both of an A- or B-annulus in a wellbore comprising at least an A- and B-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string, or (4) in one or more of an A-, B- or C-annulus in a wellbore comprising at least an A-, B- and C-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string.
Yet alternatively, one or more strings of pipe may simply run through a conduit or outer pipe(s) to connect one or more wellbores to another wellbore or to lead from one or more wellbores to a centralized gathering or processing center; and said annular fluid may have been emplaced within said conduit or pipe(s) but external to said one or more strings of pipe therein. Insulating annular fluids or insulating packer fluids are annular fluids or packer fluids used to control heat loss—both conductive and convective heat losses. These insulating annular or packer fluids are used in oil or gas well construction operations conducted in low temperature venues of the world, for example, those areas having permafrost.
Permafrost is a thick layer of frozen surface ground found often in arctic or antarctic regions, which frozen ground may be several hundred feet thick and presents a great obstacle to the removal of relatively warm fluids through a well pipe penetrating said frozen ground. Particularly, warm fluid in the well pipe causes thawing of the permafrost in the vicinity of the well resulting in subsidence which can irreparably impair the permafrost environment and impose compressive and/or tension loads high enough to rupture or collapse the well casing and hence allow the escape of well fluids. In addition, the warm gas or oil coming to the surface in the well pipe becomes cooled by giving up its heat to the permafrost. Further, gas hydrate crystals may form, which can freeze together and block the well pipe; alternatively, wax or asphaltenes may form, which can agglomerate and block the well pipe. Generally, except for a tiny contribution from radiation, annular heat loss is due to convection and to conduction.
Conditions where the drill string are in contact with large bodies of water, such as deepwater operations, may also require thermal isolation of production fluids from the surrounding environment. Deepwater drilling is carried out under high bottom hole temperatures and pressures. The deepwater wells stretch to several thousand meters in depth, where the majority of the well string is in direct contact with ocean waters. Contact of the surrounding waters with the drill string may result in the rapid transfer of heat, leading to the formation of gas hydrates as described above.
Heavy oil production is another operation which often can benefit from the use of an insulating annular fluid. In heavy oil production, a high-pressure steam or hot water is injected into the well and the oil reservoir to heat the fluids in the reservoir, causing a thermal expansion of the crude oil, an increase in reservoir pressure and a decrease of the oil's viscosity. In this process, damage to the well casing may occur when heat is transferred through the annulus between the well tubing and the casing. The resulting thermal expansion of the casing can break the bond between the casing and the surrounding cement, causing leakage. Accordingly, an insulating medium such as a packer fluid may be used to insulate or to help insulate the well tubing. The packer fluid also reduces heat loss and saves on the energy requirements in stimulation using hot-water or steam (huff-n-puff) or in hot-water- or steam-flooding.
In addition to steam injection processes and operations which require production through a permafrost layer, subsea fields—especially, subsea fields in deep water, 1,500 to more than 6,000 feet deep—require specially designed systems, which may require an insulating annular or packer fluid. For example, a subsea oil reservoir temperature may be between about 120° F. and 250° F., while the temperature of the water through which the oil may be conveyed is often as low as 32° F. to 50° F. Conveying the high temperature oil through such a low temperature environment can result in oil temperature reduction and consequently the separation of the oils into various hydrocarbon fractions and the deposition of paraffins, waxes, asphaltenes, and gas hydrates. The agglomeration of these oil constituents can cause blocking or restriction of the wellbore, resulting in significant reduction or even catastrophic failure of the production operation.
To meet the above-discussed insulating demands, a variety of packer fluids have been developed. For example, U.S. Pat. No. 3,613,792 describes an early method of insulating wellbores. In U.S. Pat. No. 3,613,792, simple fluids and solids are used as the insulating medium. U.S. Pat. No. 4,258,791 improves on these insulating materials by disclosing an oleaginous liquid such as topped crude oils, gas oils, kerosene, diesel fluids, heavy alkylates, fractions of heavy alkylates and the like in combination with an aqueous phase, lime, and a polymeric material. U.S. Pat. No. 4,528,104 teaches a packer fluid comprised of an oleaginous liquid such as diesel oil, kerosene, fuel oil, lubricating oil fractions, heavy naphtha and the like in combination with an organophillic clay gellant and a clay dispersant such as a polar organic compound and a polyfunctional amino-silane.
Gelled hydrocarbons have been successfully used as packer fluids because the hydrocarbon fluids have low thermal conductivities, while gel formation increases the viscosities of the fluids. The increased viscosity minimizes fluid movement in packer fluids, leading to reduced or minimized convective heat loss.
Polyvalent metal (such as ferric iron or aluminum) salts of phosphoric acid esters have been successfully used as gelling agents for forming high viscosity gelled hydrocarbon fluids. Description of these fluids and their uses can be found in U.S. Pat. No. 4,507,213 issued to Daccord et al., U.S. Pat. No. 4,622,155 issued to Harris et al., U.S. Pat. No. 5,190,675 issued to Gross, and U.S. Pat. No. 5,846,915 issued to Smith et al. More recently, U.S. Pat. No. 6,511,944 issued to Taylor et al. discloses gelled hydrocarbon fracture fluids that include ferric iron or aluminum polyvalent metal salts of phosphonic acid esters, instead of phosphoric acid esters.
Typical hydraulic fracturing fluids have limited stability. Hydraulic fracturing often involves up to 2,000,000 pounds of proppant and operations may be concluded in less than 8 hours.